Method for pre-treatment of subterranean sites adjacent to water injection wells

ABSTRACT

A method to improve the effectiveness of MEOR or bioremediation processes has been disclosed. In this method toxic chemicals accumulated in subterranean sites adjacent to the water injection wells are either dispersed or removed prior to introduction of microbial inocula for enhanced microbial oil recovery or bioremediation of these sites.

FIELD OF THE INVENTION

The invention relates to the field of microbial enhanced oil recoveryand bioremediation of subterranean contaminated sites. Specifically, itrelates to methods of treating the toxic chemicals accumulated insubterranean sites adjacent to the water injection wells prior tointroduction of microbial inocula for microbial enhanced oil recovery orbioremediation of these sites.

BACKGROUND OF THE INVENTION

Traditional oil recovery techniques which utilize only the naturalforces present at an oil well site, allow recovery of only a minorportion of the crude oil present in an oil reservoir. Oil well sitegenerally refers to any location where wells have been drilled into asubterranean rock containing oil with the intent to produce oil fromthat subterranean rock. An oil reservoir typically refers a deposit ofsubterranean oil. Supplemental recovery methods such as water floodinghave been used to force oil through the subterranean location toward theproduction well and thus improve recovery of the crude oil (Hyne, N.J.,2001, “Non-technical guide to petroleum geology, exploration, drilling,and production”, 2nd edition, Pen Well Corp., Tulsa, Okla., USA).

To meet the rising global demand on energy, there is a need to furtherincrease production of crude oil from oil reservoirs. An additionalsupplemental technique used for enhancing oil recovery from oilreservoirs is known as Microbial Enhanced Oil Recovery (MEOR) asdescribed in U.S. Pat. No. 7,484,560. MEOR, which has the potential tobe a cost-effective method for enhanced oil recovery, involves eitherstimulating the indigenous oil reservoir microorganisms or injectingspecifically selected microorganisms into the oil reservoir to producemetabolic effects that lead to improved oil recovery.

The production of oil and gas from subterranean oil reservoirs requiresinstalling various equipment and pipelines on the surface or thesubterranean sites of the oil reservoir which come in contact withcorrosive fluids in gas- and oil-field applications. Thus, oil recoveryis facilitated by preserving the integrity of the equipment needed toprovide water for water injection wells and to convey oil and water fromthe production wells. As a result, corrosion can be a significantproblem in the petroleum industry because of the cost and downtimeassociated with replacement of corroded equipment.

Sulfate reducing bacteria (SRB) microorganisms, which produce hydrogensulfide (H₂S), are amongst the major contributors to corrosion offerrous metal surfaces and oil recovery equipment. These microorganismscan cause souring, corrosion and, plugging and thus can have negativeimpact on a MEOR or a bioremediation process. Bioremediation refers toprocesses that use microorganisms to cleanup oil spills or othercontaminants from either the surface or the subterranean sites of soil.

To combat corrosion, corrosion inhibitors—which are chemicals or agentsthat decrease the corrosion rate of a metal or an alloy and are oftentoxic to microorganisms—are used to preserve the water injection and oilrecovery equipment in such wells. In the practice of the presentinvention a water injection well is a well through which water is pumpeddown into an oil producing reservoir for pressure maintenance, waterflooding, or enhanced oil recovery. The significant classes of corrosioninhibitors include compounds such as: inorganic and organic corrosioninhibitors. For example, organic phosphonates, organic nitrogencompounds, organic acids and their salts and esters (Chang, R. J. etal., Corrosion Inhibitors, 2006, Specialty Chemicals, SRI Consulting).

US2006/0013798 describes using bis-quaternary ammonium salts ascorrosion inhibitors to preserve metal surfaces in contact with thefluids to extend the life of these capital assets.

U.S. Pat. No. 6,984,610 describes methods to clean up oil sludge anddrilling mud residues from well cuttings, surface oil well drilling andproduction equipment through application of acids, pressure fracturingand acid-based microemulation for enhanced oil recovery.

WO2008/070990 describes preconditioning of oil wells usingpreconditioning agents such as methyl ethyl ketone, methyl propyl ketoneand methyl tertiary-butyl ether in the injection water to improve oilrecovery. Mechanisms such as modifying the viscosity of the oil in thereservoir and enlivening the heavy oil were attributed to this method.

US2009/0071653 describes using surfactants, caustic agents, anti-cakingagents and abrasive agents to prevent or remove the build-up of fluidfilms on the processing equipment to increase the well's capacity.

Studies indicate that long-term addition of chemicals or agents used tocontrol undesirable events such as corrosion, scale, microbialactivities, and foam formation in the water supply of a water injectionwell does not lead to their accumulation in high enough concentrationsto adversely affect the microorganisms used in MEOR (Carolet, J-L. in:Ollivier and Magot ed., “Petroleum Microbiology”, chapter 8, pages164-165, 2005, ASM press, Washington, D.C.).

However, viability of microorganisms used in MEOR or bioremediationprocesses is a concern. It can be desirable to modify MEOR orbioremediation treatments such that the viability of microorganisms usedduring MEOR is maintained throughout the oil recovery process such thatMEOR or bioremediation processes become more effective.

SUMMARY OF THE INVENTION

The present disclosure relates to a method for improving theeffectiveness of a MEOR or bioremediation process by detoxifyingsubterranean sites adjacent to oil wells, wherein the wells have beenpreviously treated with corrosion inhibitors prior to inoculation of themicroorganisms required for MEOR or bioremediation.

In one aspect the present invention is an oil recovery method comprisingthe steps of:

-   -   a) treating a subterranean site in a zone adjacent to a water        injection well with a detoxifying agent wherein, prior to the        treatment, corrosion inhibitors and their degradation products        have been adsorbed into the zone and have accumulated to        concentrations that are toxic to microorganisms used in        microbial enhanced oil recovery and/or bioremediation processes,        and thereby have formed a toxic zone, and    -   b) adding an inoculum of microorganisms wherein the        microorganisms comprise one or more species of: Comamonas,        Fusibacter, Marinobacterium, Petrotoga, Shewanella, Pseudomonas,        Vibrio, Petrotoga, Thauera, and Microbulbifer useful in        microbial enhanced oil recovery to the water injection well;        wherein the corrosion inhibitor comprises an organic compound        selected from the group consisting of organic phosphonates,        organic nitrogen compounds such as amines, organic acids and        their salts and esters, carboxylic acids and their salts and        esters, sulfonic acids and their salts.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is the schematic representation of a water injection well and thesubterranean sites adjacent to the water injection well. (1) is the flowof injection water into the well casing (7), (2 and 3) are rock layers,(4) is the perforations in the casing, (5) is the well bore, (6) is theface of the rock layer made by the well bore, (7) is the well casing,(8) is one side of the watered zone that is axis-symmetric with theinjection well, shown by a dotted box in the rock layer (3).

FIG. 2 is the schematic of a model system used to simulate formation ofa toxic zone. (9) is a long slim tube; (10) is a pressure vessel toconstrain the slim tube; (11 and 12) are the opposite ends of thepressurized vessel; (13) is a pump; (14) is the feed reservoir; (15) isthe water inlet for the pressure vessel; (16) is the back pressureregulator; (17) is the high pressure air supply; (18) is an inletfitting connecting the slim tube inside the pressure vessel to the pumpand pressure transducers; (21) is an outlet fitting connecting the slimtube inside the pressure vessel to the back pressure regulator and thelow side of the differential pressure transducer; (19) is a differentialpressure transducer; and (20) is an absolute pressure transducer.

FIG. 3 depicts titration of amine coated core sand; ♦ represent aminecoated sand and □ represent first derivative of the titration curve(central differences).

FIG. 4 depicts titration of brine and core sand with 1N HCl; ▪ representbrine #1 with 10 grams of core sand; diamonds ♦ represent brine #1 only;

represents the slope of brine #1 with 10 grams of core sand; and Δrepresents the slope of brine #1 only.

FIG. 5 depicts titration of brine and core sand with 10% nitric acid; ♦represent the concentration of amine observed in solution for a givenpH.

FIG. 6 depicts titration of brine and core sand with 10% acetic acid; ♦represent the concentration of amine observed in solution for a givenpH.

DETAILED DESCRIPTION OF THE INVENTION

In one aspect, the present invention is a method for detoxifying thecorrosion inhibitors and their degradation products in a subterraneansite adjacent to a water injection well of an oil well site. Applicantshave found that oil recovery processing aids—such as corrosioninhibitors, for example—can accumulate in the area adjacent to the waterinjection well and build to concentrations that are toxic tomicroorganisms used in MEOR or bioremediation. As the term is usedherein, “detoxifying” or “detoxification of” a water injection sitemeans removing or reducing the toxicity caused by corrosion inhibitorsand their degradation products to microorganisms to allow their growthand activity of said microorganisms, used in MEOR or bioremediation.

For the purposes of the present invention, the term “toxic zone” refersto a subterranean site adjacent to the water injection well comprisingtoxic concentrations of agents such as corrosion inhibitors or theirdegraded products which have adverse effects on growth and metabolicactivities of microorganisms used in MEOR and/or bioremediation. A toxicagent, as the term is used herein, is any chemical or biological agentthat adversely affects growth and metabolic functions of microorganismsused in MEOR and/or bioremediation.

FIG. 1 is a schematic of a subterranean site adjacent to a waterinjection well. The injection water (1) flows into the well casing (7)which is inside the well bore (5) drilled through rock layers (2 and 3).A gap exists between the well casing (7) and the face (6) of the rocklayer made by the well bore (5). Rock layer (2) represents impermeablerock above and below a permeable rock (3) that holds or traps the oil.The injection water (1) flows down the well casing (7) and passesthrough perforations in the casing (5) and into fractures (4) in thepermeable rock (3). This injection water then flows through thepermeable rock layer (3) and displaces oil from a watered zone (8)adjacent to the well bore. This zone extends radially out from the wellbore (5) in all directions in the permeable rock layer (3). While thevolume of permeable rock (3) encompassed by the dash line (8) isillustrated only on one side of the well bore it actually exists on allsides of the well bore. This watered zone represents the subterraneansite adjacent to the water injection well.

Corrosion inhibitors that can accumulate to levels that are toxic tomicroorganisms used in MEOR are, for example: inorganic corrosioninhibitors such as chlorine, hypochlorite, bromine, hypobromide andchlorine dioxide. Those used to combat corrosion caused by SRBmicroorganisms include, but are not limited to: nitrates (e.g., calciumor sodium salts), nitrite, molybdate, (or a combination of nitrate,nitrite and molybdate), anthraquinone, phosphates, salts containingchrome and zinc and other inorganics, including hydrazine and sodiumsulfite (Sanders and Sturman, chapter 9, page 191, in: “Petroleummicrobiology” page 191, supra and Schwermer, C. U., et al., Appl.Environ. Microbiol., 74: 2841-2851, 2008).

Organic compounds used as corrosion inhibitors include: acetylenicalcohols, organic azoles, gluteraldehyde, tetrahydroxymethyl phophoniumsulfate (THPS), bisthiocyanate acrolein, dodecylguanine hydrochloride,formaldehyde, chlorophenols, organic oxygen scavengers and variousnonionic surfactants.

Other organic corrosion inhibitors include, but are not limited to:organic phosphonates, organic nitrogen compounds including primary,secondary, tertiary or quaternary ammonium compounds (hereinafterreferred to generically as “amines”), organic acids and their salts andesters, carboxylic acids and their salts and esters, sulfonic acids andtheir salts.

Applicants have determined that corrosion inhibitors can accumulate byadsorption into or on the subterranean site (e.g., sand stone,unconsolidated sand or limestone) or into the oil that has been trappedin the oil reservoir subterranean site. Long-term addition of thesechemicals results in their accumulation and formation of a toxic zone insubterranean sites adjacent to the water well with adverse effects onmicrobial inocula intended for MEOR and/or bioremediation applications.

A model system to simulate formation of a toxic zone can be used tostudy its effects on the survival of microorganisms. For example, amodel system called a slim tube can be set up and packed with core sandfrom an oil well site. The model system as described herein can be setup using tubing, valves and fittings compatible with the crude oil orthe hydraulic solution used that can withstand the range of appliedpressure during the process. An absolute pressure transducer,differential pressure transducer and back pressure regulator for Examplemade by (Cole Plamer, Vernon hill, IL and Serta, Boxborough, Mass) arerequired and are commercially available to those skilled in the art.

The model toxic zone can be established using solutions of amines and/oramine mixtures and flushing them through a tube packed with core sandfrom an oil reservoir. Other corrosion inhibitors suitable for use inconstructing a model can comprise organic phosphonates or anthraquinoneor phosphates. The concentration of the corrosion inhibitors used tocreate the model toxic zone may be from 0.01 to 100 parts per million.

Detoxification of the toxic zone involves degradation, desorption ordispersion of the accumulated toxic chemicals or agents usingdetoxifying agents. The term “detoxifying agent” therefore refers to anychemical that either disperses or destroys the toxic chemicals andagents described herein and renders them non-toxic to microorganisms.

Detoxification of the chemicals accumulated in the toxic zone may beachieved using a degradation agent. A degradation agent, as the term isused herein, is an agent that destroys or assists in the destruction oftoxic agents found in the toxic zone. Degradation agents can include,for example, strong oxidizers that chemically react with corrosioninhibitors when added to the injection water and degrade them into lesstoxic or non-toxic products. Degradation agents include strong oxidizingagents such as, for example, nitrates, nitrites, chlorates,percholorates and chlorites.

Detoxification of the chemicals accumulated at the toxic zone may alsobe achieved using a dispersing agent. A “dispersing agent” as the termis used herein includes any chemical that lowers the pH of the solution,ionizes the amines and solubilizes them into the water during waterflooding and allows for natural dispersion and diffusion to lower theconcentration where it is no longer toxic to MEOR or bioremediationmicroorganisms. For example, amines are fairly non-reactive under mildconditions, however, they become ionized at lower pH. Thus treatment ofthe amines with an acid increases their solubility and releases themfrom oil and/or from rocks and disperses them from the toxic zone. Thesolubilized amines may therefore enter into the water flowing throughthe well. A combination of radial flow, dispersion and desorption mayallow the solubilized amines to be diluted and dispersed over a largearea (from at least 10 to about 200 feet (from at least 3 meters toabout 7 meters)) of the oil well. Following dilution and dispersion ofthe amines over a much larger area, their concentrations within thesubterranean site of the well would have been consequently reduced tonon-toxic levels for MEOR or bioremediation microorganisms. However,even if the amines concentrations were still at toxic levels, the toxiczone in the subterranean site adjacent to the injector well will havebecome non-toxic to microorganisms. Thus, the microbial inoculum maypass through the subterranean site adjacent to the water injection wellwithout encountering toxic levels of the amines.

In another embodiment, hydrogen peroxide may be added to the toxic zone,as both a degradation and a dispersing agent, from about 1,000 parts permillion to 70,000 parts per million by volume of water. In anotherembodiment, perchlorates may be added, as both a degradation and adispersing agent, from about 1 parts per million to about 10,000 partsper million.

In another embodiment, any acid capable of lowering the pH at least 1unit less than the equivalence point of the amine (as measured in theExamples below) may be used. The acid used to ionize the amines mayinclude, but is not limited to, nitric acid, acetic acid, oxalic acid,hydrofluoric acid, and hydrochloric acid. Acid may be added from about0.1 weight % to about 20 weight % to the water that is being pumped intothe toxic zone.

In a MEOR process, viable microorganisms are added to the water beinginjected into the water injection well. The term “inoculum ofmicroorganisms” refers to the concentration of viable microorganismsadded. These microorganisms colonize, that is to grow and propagate, atthe subterranean sites adjacent to the water injection well to performtheir MEOR.

Microorganisms useful for this application may comprise classes offacultative aerobes, obligate anaerobes and denitrifiers. The inoculummay comprise of only one particular species or may comprise two or morespecies of the same genera or a combination of different genera ofmicroorganisms.

The inoculum may be produced under aerobic or anaerobic conditionsdepending on the particular microorganism(s) used. Techniques andvarious suitable growth media for growth and maintenance of aerobic andanaerobic cultures are well known in the art and have been described in“Manual of Industrial Microbiology and Biotechnology” (A. L. Demain andN. A. Solomon, ASM Press, Washington, D.C., 1986) and “Isolation ofBiotechnological Organisms from Nature”, (Labeda, D. P. ed. p 117-140,McGraw-Hill Publishers, 1990).

Examples of microorganisms useful in MEOR in this application include,but are not limited to: Comamonas terrigena, Fusibacter paucivorans,Marinobacterium georgiense, Petrotoga miotherma, Shewanellaputrefaciens, Pseudomonas stutzeri, Vibrio alginolyticus, Thaueraaromatica, Thauera chlorobenzoica and Microbulbifer hydrolyticus.

In one embodiment an inoculum of Shewanella putrefaciens (ATCC PTA-8822)may be used to inoculate the slim tube test. In another embodimentPseudomonas stutzeri (ATCC PTA8823) may be used to inoculate the slimtube. In another embodiment Thauera aromatica (ATCC9497) may be used toinoculate the slim tube.

The inoculum of microorganisms useful for bioremediation may comprise,but are not limited to, various species of: Corynebacteria, Pseudomonas,Achromobacter, Acinetobacter, Arthrobacter, Bacillus, Nocardia, Vibrio,etc. Additional useful microorganisms for bioremediation are known andhave been cited, for example, in Table 1 of U.S. Pat. No. 5,756,304,columns 30 and 31.

The inoculum for injecting into the water well injection site maycomprise one or more of the microorganisms listed above.

EXAMPLES

The present invention is further defined in the following Examples. Itshould be understood that these Examples, while indicating preferredembodiments of the invention, are given by way of illustration only.From the above discussion and these Examples, one skilled in the art canascertain the essential characteristics of this invention, and makevarious changes and modifications to the invention to adapt it tovarious uses and conditions.

General Methods Chemicals and Materials

All reagents, and materials used for the growth and maintenance ofmicrobial cells were obtained from Aldrich Chemicals (Milwaukee, Wis.),DIFCO Laboratories (Detroit, Mich.), GIBCO/BRL (Gaithersburg, Md.), orSigma Chemical Company (St. Louis, Mo.), unless otherwise specified.

Amines Analysis

Concentration of amines, in media and water, were analyzed by gaschromatography (GC). An Agilent Model 5890 (Agilent, Wilmington, Del.),GC equipped with a flame photoionization detector and a split/splitlessinjector, a DB-FFAP column (30 meter length×0.32 millimeter (mm)depth×0.25 micrometer particle size). The equipment had an Agilent ALSAutoinjector, 6890 Model Series with a 10 milliliter (ml) syringe. Thesystem was calibrated using a sample of N,N-Dimethyl-1-Dodecaneamine(Aldrich). Helium was used as the carrier gas. A temperature gradient of50 degrees Celsius (° C.) to 250° C. at 30° C. increase per minute (min)was used. Retention times (in minutes, min) for various chemicals ofinterest included: N,N-Dimethyl-1-Dodecaneamine (8.08 min);N,N-Dimethyl-1-Tetradecaneamine (8.85 min);N,N-Dimethyl-1-Hexadecane-amine (9.90 min);N,N-Dimethyl-1-Octadecaneamine (10.26 min) andN-Methyl,N-Benzyl)-1-Tetradecaneamine (11.40 min).

Example 1 Establishing a Toxic Zone in Core Sand from an Oil Well Usinga Mixture of Amines in a Model System

A sample of the sand obtained from the Schrader Bluff formation at theMilne Point Unit of the Alaska North Slope was cleaned by washing with asolvent made up of a 50/50 (volume/volume) mixture of methanol andtoluene. The solvent was subsequently drained and then evaporated offthe core sand to produce clean, dry, flow able core sand. This core sandwas sieved to remove particles with less than one micrometer in size andwas then packed tightly into a four foot (121.92 cm) long flexible slimtube (9) and compacted by vibration using a laboratory engraver. Bothends of the slim tubes were capped to keep the core sand in it. Thecomplete apparatus is shown in FIG. 2. Tubing that can sustain theamount of pressures used in the slim tube, was connected to the endcaps. The slim tube (9) was mounted into the pressure vessel (10) withtubing passing through the ends (11 and 12) of the pressure vessel usingpressure fittings (18 and 21). Additional fittings and tubing were usedto connect the inlet of the slim tube (11) to a pressure pump (13) and afeed reservoir (14).

Additional fittings and tubing connected the inlet of the slim tube toan absolute pressure transducer (20) and the high pressure side of adifferential pressure transducer (19). Fittings and tubing connected theoutlet of the slim tube (12) to the low pressure side of a differentialpressure transducer (19) and to a back pressure regulator (16). Thesignals from the differential pressure and the absolute pressuretransducer were ported to a computer and the pressure readings weremonitored and periodically recorded. The pressure vessel (10) around theslim tube was filled with water through a water port (15). This waterwas then slowly pressurized with air (17) to a pressure of about 105 persquare inch (psi) (0.72 mega Pascal) while brine #1 from the feedreservoir (14) (Table 1) flowed through the slim tube and left the slimtube through the back pressure regulator (16). This operation wasperformed such that the pressure in the slim tube was always 5 to 20 psi(0.034-0.137 mega Pascal) below the pressure in the pressure vessel(10).

TABLE 1 Ingredients of Brine #1 (no nutrient brine - gram per liter(gr/L) of tap water NaHCO₃ 1.38 grams (gr) CaCl₂*6H₂O 0.39 gr MgCl₂*6H₂O0.220 gr KCl 0.090 gr NaCl 11.60 gr NaHCO₃ 1.38 gr Trace metals 1 mlTrace vitamins 1 ml Na₃(PO₄) 0.017 gr (=10 parts per million (ppm) PO₄)NH4Cl 0.029 gr (=10 ppm NH₄) Acetate 0.2 gr (200 ppm acetate) The pH ofbrine #1 was adjusted to 7.0 with either HCl or NaOH and the solutionwas filter sterilized.

TABLE 2 Concentration of the amines added to Brine #1 Minor otherNN-Dimethyl-1- NN-Dimethyl-1- NN-Dimethyl- N-methylN- amine amineDodecaneamine tetradecaneamine Methanethioamide ?? CaprolactamBenzyl-1-tetradecaneamine Sample PPM PPM PPM PPM PPM PPM PPM Brine #1 w/25 124 23 1 0 0 2 amine

Once the pressure inside and outside the slim tube was established, onepore volume of the crude oil from an oil reservoir of the Milne PointUnit of the Alaskan North Slope was pumped into the slim tube. Thisprocess was performed in several hours (h). Once the crude oil hadsaturated the core sand in the slim tube and was observed in theeffluent, the flow was stopped and the oil was allowed to age in thecore sand for 3 weeks. At the end of this time, brine #1 was pumpedthrough the slim tube at a rate of ˜1.5-3.5 milliliter per hour (ml/h)(˜1 pore volume every 20 h). Samples were taken from the effluent andthe concentration of natural microflora in them was determined.

After 51 pore volumes of flow through the slim tube the concentration ofnatural microflora in the system was about 1×10⁷ colony forming unitsper milliliter (CFU/ml). At this point, a mixture of amines (hereafteramines/brine mixture) was added at 150 ppm concentration to brine #1.The approximate composition of the mixture of amines (Table 2) consistedof 7 different amine components that were identified. Five wereidentified by Mass Spectrometry (Agilent Technologies, Inc. Santa Clara,Calif.) as N-N-dimethyl-1-dodecaneamine,N-N-dimethyl-1-tetradecane-amine, N-N-dimethyl-methane-thioamide,caprolactam and N-methyl-N-benzyl-1-tetradecaneamine. Two of thecomponents were identified as amines but specific chemical formulascould not be assigned to them because the Mass Spectral Fragmentationpatterns could not be deciphered. These are labeled in Table 2 as “minoramine” and “other amine”. Analysis of the effluent from the slim tubedid not indicate presence of any amines in it. The experiment wascontinued by pumping 150 ppm of the mixture of amines in brine #1through the slim tube.

After 77 pore volumes of the mixture of brine #1 with 150 ppm of mixtureof amines was pumped into the slim tube no amines were observed in theeffluent.

After 80 pore volumes of the mixture of brine #1 with 150 ppm of mixtureof amines was pumped into the slim tube a total of about 1 gr of themixture of amines had flowed through the slim tube. At this point, 80ppm of amines was finally observed in the effluent of the slim tube.This very long delay in seeing the amines in the effluent means thatvirtually all the amines had been trapped in the slim tube. In addition,at this time, no natural microflora could be seen in the effluentindicating that the slim tube had become toxic enough to kill allexisting microflora. At this point, pumping the amines-free brine#1 wasstarted in an attempt to flush the amines out of the slim tube and tomake it less toxic.

After 24 pore volumes of the amines-free brine#1 had been pumped throughthe slim tube, 51 ppm of amines was detected in the effluent. The slimtube was then inoculated with one pore volume of Shewanella putrefaciens(ATCC PTA-8822) at a concentration of approximately 1×10⁹ CFU/ml. Thisinoculation was not allowed to remain in the slim tube. Instead,amines-free brine#1 was flushed through the slim tube immediately afterthe inoculation. Consequently the microbes resided in the slim tube foronly a few hours during the transit through it. Thus, it was anticipatedthat the microorganisms' concentration in the effluent could be measuredin the effluent eluting the slim tube. However, remarkably nomicroorganisms (representing about a 9 log kill) were detected in theslim tube effluent despite the short residence time of the inoculum inthe slim tube. This experiment confirmed that a toxic zone had beenestablished in the slim tube. In a continued attempt to detoxify theslim tube, brine #1 alone was continuously pumped through it.

After 79 pore volumes of the amines-free brine #1 had been pumpedthrough the slim tube, the amines concentration in the effluent of theslim tube was measured at 30 ppm. The slim tube was inoculated withanother pore volume of Shewanella putrefaciens (at 1×10⁹ CFU/ml). TheCFU/ml in an effluent sample was about 1×10⁴ showing more than a 5 logkill of this microorganism had occurred immediately followinginoculation. This experiment underlined the continued toxic effect ofthe amines despite extended washing of the tube with the amines-freebrine#1 solution.

After 108 pore volumes of the amines-free brine #1 had been pumpedthrough the slim tube, the amine concentration in the effluent wasmeasured at 5 ppm. The slim tube was inoculated with an additional onepore volume of Shewanella putrefaciens containing 1×10⁹ CFU/ml. TheCFU/ml in the effluent sample of the slim tube immediately followinginoculation indicated a 4-5 log kill of this microorganism despite theextended washing with the amines-free brine#1 and the decrease in theamines concentration in the effluent. These results further confirmedthe continued toxic effect of the mixture of amines accumulated in theslim tube.

After 143 pore volumes of the amines-free brine #1 had been pumpedthrough the slim tube one pore volume of an inexpensive odorless mineralspirits (OMS)(Parks OMS, Zinsser Co., Inc., Somerset Jew Jersey #2035CAS #8052-41-3) was pumped through the slim tube in an attempt to removethe remaining mixture of amines. After this flush of OMS, pumping ofamines-free brine #1 through the slim tube was continued.

After 149 pore volumes of amines-free brine #1 had been pumped throughthe slim tube, the amines concentration in the effluent was measured at4 ppm and the slim tube was inoculated with an additional one porevolume of Shewanella putrefaciens (1×10⁹ CFU/ml). A count ofmicroorganisms in the sample of the slim tube's effluent showed a 2-3log kill (99 to 99.9%) despite the OMS flush and the extended washingwith the amines-free brine#1. These results confirmed that the toxiczone in the slim tube was still killing virtually all the microorganismsadded to the tube.

After 168 pore volumes of the amines-free brine #1 had been pumpedthrough the slim tube, one pore volume of a solution of 10% HCl in waterwas pumped through the slim tube to remove the amines. After this acidwash, the amines-free brine #1 was continuously pumped through the slimtube.

Following the acid wash treatment, an additional 2 pore volumes of theamines-free brine #1 was pumped through the slim tube and the aminesconcentration in the effluent was measured at 0.5 ppm. The slim tube wasthen inoculated with an additional one pore volume of Shewanellaputrefaciens (1×10⁹ CFU/ml). The CFU/ml in the effluent showed about a0.4 log kill of this microorganism. These results underlined survival ofmore microorganisms following the acid wash of the slim tube and theeffectiveness of using an acid to detoxify the toxic zone in the slimtube. Table 3 below summarizes results of the various tests describedabove.

TABLE 3 Summary of the amount of amine observed in the slim tube'seffluent and the fraction of the microorganisms killed (log kill) duringresidence in the slim tube. Total Pore volume of fluid ppm pumped amineslog kill through slim in the after tube effluent inoculating 51 0 0  131 80.5 nd amines flood stopped 155 51.1 9.6 210 29.5 5.3 (at least)239 4.7 4.5 (at least) 274 OMS flooded ~1 pore volume 280 4.2 2.4 29910% HCL flooded for 1 PV 301 0.5 0.4 PV = pore volume; nd = not detected

Example 2 Removal of N N-Dimethyl-1-Dodecanamine from Core Sand Throughtheir Ionization at Low pH Using Hydrochloric Acid

38 milligrams (mg) of N N-Dimethyl-1-Dodecanamine (hereafter referred toas “the amine”) was added to 10.210 gr of Pentane. This solution wasadded to 10.1845 gr of specific sand layers (Oa and Ob) obtained fromthe Schrader Bluff formation of the Milne Point Unit of the AlaskanNorth slope. The oil content of the sand was first removed using amixture of methanol and toluene (50/50, volume/volume) as solventwashes. The solvent mixture was subsequently evaporated off the coresand to produce clean, dry, flowable core sand. This sand was mixed withthe amine and pentane solution to produce a slurry. This slurry wasthoroughly mixed and the pentane was evaporated off leaving the amine onthe sand (hereafter referred to as sand/amine mixture). 100 ml of brine#2 (Table 3) was added to the sand/amine mixture to create thesand/amine/brine mixture. The initial pH of the sand/amine/brine mixturewas 8.4. The concentration of the amine in the water should have been380 ppm if all the amine were dissolved in brine #2. Analysis of asample of sand/amine/brine mixture by GC did not reveal the presence ofany amines in the test sample (i.e., the amine conc. was ˜<1 ppm). Thefact that the amine was not detected underlined its strong binding tothe sand particles. 0.1 ml of 1 normal (N) HCl was added to thissolution, and the pH and the amine concentration was measured again.This step was repeated several times and the analyses results are shownin both Table 4 and in FIG. 3. Complete ionization and solubilization ofthe amine in the water was observed at pH below ˜6.0. This is asurprising finding since the pKa of HCl is −6.2 (Langes Handbook ofChemistry, 14^(th) edition, page 8.14, 1992, McGraw-Hill, Inc., NewYork). Therefore, the concentration of the HCl required for this step tocompletely ionize the amine and removed it from the toxic core sand maybe further reduced several orders of magnitude from the 10%concentration used in this example. The data underlines the remarkableefficiency of an acid at ionizing and removing the amine from the sand.

TABLE 3 Composition of brine #2 (gr/L of deionized water) NaHCO₃  1.38gr CaCl₂*6H₂O  0.39 gr MgCl₂*6H₂O 0.220 gr KCl 0.090 gr NaCl 11.60 gr

TABLE 4 Amine concentration measured in Example 2 N-N- First dimethyl-1-derivative dodeanamine (change in (ppm) in slim amine/change 1N HClsample tube effluent in pH) pH (ml) Amine titrate st 0.00 8.14 0.00Amine titrate 1 46.41 63.75 7.37 0.10 Amine titrate 2 59.29 63.42 7.210.10 Amine titrate 3 67.97 24.34 7.03 0.10 Amine titrate 4 74.38 160.356.59 0.10 Amine titrate 5 212.28 412.18 6.13 0.10 Amine titrate 6 288.72679.86 6.07 0.10 Amine titrate 7 273.47 −148.78 6.04 0.05 Amine titrate8 275.33 119.35 5.98 0.05 Amine titrate 9 303.31 65.90 5.79 0.05 Aminetitrate 10 314.21 15.17 5.39 0.05 Amine titrate 11 328.48 3.24 4.13 0.05Amine titrate 12 321.33 11.80 3.19 0.05 Amine titrate 13 342.88 47.422.91 0.05 Amine titrate 14 342.67 −6.52 2.74 0.05 Amine titrate 15340.92 79.86 2.61 0.05 Amine titrate 16 369.02 80.22 2.41 0.10 Aminetitrate 17 368.19 2.25 2.27 0.10 Amine titrate 18 369.54 7.51 2.18 0.10Amine titrate 19 369.47 0.12 2.10 0.10 Amine titrate 20 369.56 2.04 0.10

Example 3 Capacity of Core Sand to Neutralize Acid A. Titration of Brine#2 in the Absence of Core Sand

The intent of this experiment was to determine the capacity of the coresand described in Example 2 to neutralize the HCl intended to ionize theamine accumulated in the sand.

To set up a control test, 100 ml of brine #2 was titrated with 1 N HClto initial pH of 8.1. An aliquot (0.1 ml) of 1N HCl was added to thebrine #2 and the pH was measured. The HCl addition was repeated severaltimes and the pH was measured after each addition. Results of theseanalyses are shown in both Table 5 and in FIG. 4. The data indicatedthat about 2.25 milliequivalents of HCl were needed to achieve theequivalence point of about pH 4 corresponding to about 100% recovery ofthe carbonate present in brine #2.

TABLE 5 Titration of synthetic injection brine #2 in the absence of theamine First derivative of 1N HCl sample pH pH (ml) Addition 1 8.10 0.00Addition 2 7.67 0.73 0.10 Addition 3 7.37 0.49 0.10 Addition 4 7.18 0.350.10 Addition 5 7.02 0.29 0.10 Addition 6 6.89 0.23 0.10 Addition 7 6.790.21 0.10 Addition 8 6.68 0.19 0.10 Addition 9 6.60 0.17 0.10 Addition10 6.51 0.15 0.10 Addition 11 6.45 0.15 0.10 Addition 12 6.36 0.18 0.10Addition 13 6.27 0.18 0.10 Addition 14 6.18 0.18 0.10 Addition 15 6.090.17 0.10 Addition 16 6.01 0.17 0.10 Addition 17 5.92 0.18 0.10 Addition18 5.83 0.19 0.10 Addition 19 5.73 0.33 0.10 Addition 20 5.50 0.32 0.10Addition 21 5.41 0.33 0.10 Addition 22 5.17 0.74 0.10 Addition 23 4.671.94 0.10 Addition 24 3.23 1.86 0.10 Addition 25 2.81 0.62 0.10 Addition26 2.61 0.36 0.10 Addition 27 2.45 0.25 0.10 Addition 28 2.36 0.17 0.10Addition 29 2.28 0.10B. Titration of Brine #2 with Core Sand

100 ml of brine #2 plus 10 gr of the same core sand (brine/sand mixture)used in Example 2, was titrated with 1N HCl. The initial pH of thebrine/sand mixture was 7.88. 0.1 ml aliquots of 1N HCl were added tothis mixture repeatedly, and the pH was measured after each HCladdition. The results shown in both Table 6 and in FIG. 4 indicated thataddition of 0.3 milliequivalents of HCl was needed to achieve theequivalence point with 10 gr of sand present. The data obtained in thisexperiment underlines the slight capacity of the core sand to neutralizethe added HCl. Consequently a small concentration of an acid, such asHCl, ionized the amine associated with the core sand without gettingneutralized by reaction with the sand.

TABLE 6 Titration of brine #2 and 10 gr of core sand Brine contained1.87 gr NaHCO₃ 2.60 ml of 1N Used 10.103 gr of core sand Sample HCL atpH Slope of pH (first derivative) ml 1N HCl 1 7.88 0.00 2 7.55 0.53 0.103 7.35 0.36 0.10 4 7.19 0.30 0.10 5 7.05 0.24 0.10 6 6.95 0.20 0.10 76.85 0.18 0.10 8 6.77 0.18 0.10 9 6.67 0.17 0.10 10 6.60 0.14 0.10 116.53 0.14 0.10 12 6.46 0.13 0.10 13 6.40 0.12 0.10 14 6.34 0.13 0.10 156.27 0.13 0.10 16 6.21 0.13 0.10 17 6.14 0.15 0.10 18 6.06 0.16 0.10 195.98 0.16 0.10 20 5.90 0.17 0.10 21 5.81 0.21 0.10 22 5.69 0.29 0.10 235.52 0.34 0.10 24 5.35 0.45 0.10 25 5.07 0.80 0.10 26 4.55 1.14 0.10 273.93 1.13 0.10 28 3.42 0.86 0.10 29 3.07 0.52 0.10 30 2.90 0.33 0.10 312.74 0.24 0.10 32 2.66 0.29 0.10 33 2.45 0.34 0.20 34 2.32 0.23 0.20 352.22 0.18 0.20 36 2.14 0.20

Example 4 Removal of N—N-Dimethyl-1-Dodecanamine from Core Sand Throughtheir Ionization at Low pH Using 10% Nitric Acid

The procedure outlined in Example 2 was used to produce the sand/aminemixture except that 519 mg of the amine, 10 gr of Pentane. and 60.062 grof sand from the Oa and Ob layers were used. 29.065 gr of thissand/amine mixture was added to 100 ml of brine #2 (Table 3) to createthe sand/amine/brine mixture. The initial pH of the sand/amine/brinemixture was 8.28. The concentration of the amine in the water shouldhave been about 2000 ppm if all the amine was dissolved in brine #2.Instead, analysis of a sample of brine #2 in contact with thesand/amine/brine mixture as described above showed that the amineconcentration was ˜85 ppm, i.e., far less than what was expected. Thefact that only a small amount of the amine was detected in brine #2underlined the strong binding of the amine to the sand particles. 0.1 mlof 10 weight percent (wt %) nitric acid in water was added to thissolution, and the pH and the amine concentration were measured again.This step was repeated several times and the analyses results are shownin both Table 7 and in FIG. 5. Complete ionization and solubilization inthe water of the amine was observed at a pH below ˜6.7. This is asurprising finding since the pKa of nitric acid is −1.37 (LangesHandbook of Chemistry, 14^(th) edition, page 8.15, 1992, McGraw-Hill,Inc., New York), the concentration of the nitric acid required for thisstep may be further reduced several orders of magnitude from the 10 wt %used in this experiment without any negative impact on removal of theamines from the core sand.

TABLE 7 Amine concentration measured in Example 4 ppm N-N- dimethyl-1-sample dodeanamine pH ml 10% HNO₃ start 85 8.28 0  1 110 8.13 0.1  2 2117.72 0.1  3 216 7.42 0.1  4 235 7.25 0.1  5 540 7.2 0.1  6 745 7.29 0.1 7 1153 7.33 0.1  8 1210 7.29 0.1  9 1327 7.18 0.1 10 1315 7.11 0.1 111413 6.99 0.1 12 1667 6.85 0.1 13 1897 6.73 0.1 14 1853 6.64 0.1 15 18586.59 0.1 16 1788 6.28 0.2 17 1822 5.8 0.2 18 1975 3.46 0.2

Example 5 Removal of N—N-Dimethyl-1-Dodecanamine from Core Sand Throughits Ionization at Low pH Using 10% Acetic Acid

The same procedure outlined in Example 4 was repeated here to producethe sand/amine mixture. 30.85 grams (gr) of the sand/amine mixture wasadded to 100 ml of brine #2 (Table 3) to create the sand/amine/brinemixture. The initial pH of the sand/amine/brine mixture was 8.52. Theconcentration of the amine in the water should have been about 2000 ppmif all the amine were dissolved in brine #2. Instead, analysis of brine#2 in contact with the sand/amine/brine mixture, as described above,showed that the amine concentration was ˜67 ppm, i.e., far less thanwhat was expected. The fact that only a small amount of the amine wasdetected in the brine #2 underlined the strong binding of the amine tothe sand particles. 0.1 ml of 10 wt % acetic acid was added to thissolution, and the pH and the amine concentration were measured again.This step was repeated several times and the analyses results are shownin both Table 8 and in FIG. 6. Complete ionization and solubilization inthe water of the amine was observed at pH below ˜6.7. This is asurprising finding since the pKa of acetic acid is 4.756 (LangesHandbook of Chemistry, 14^(th) edition, page 8.19, 1992, McGraw-Hill,Inc., New York). Consequently, the concentration of the acetic acidrequired for this step may be further reduced significantly from whatwas used in this example without any negative impact on removal of theamine from the core sand.

The observations described above illustrate that a weak organic acid,like acetic acid can be as effective as a strong inorganic acid, likehydrochloric acid, at ionizing and separating the amines from the toxiccore sand. It can therefore be concluded that to remove the toxic zonefrom a subterranean site, any acid that decreases the pH of a solutionbelow about 6.7 can be used.

TABLE 8 Amine concentration measured in Example ppm N-N- dimethyl-1-sample dodeanamine pH ml 10% acetic acid start 67 8.52 0  1 63 8.01 0.1 2 107 7.41 0.1  3 215 7.4 0.1  4 497 7.37 0.1  5 512 7.23 0.1  6 9697.12 0.1  7 1239 6.98 0.1  8 1453 6.89 0.1  9 1583 6.75 0.1 10 1579 6.560.1 11 1616 6.39 0.1 12 1759 6.4 0.1 13 1736 6.02 0.2 14 1718 5.4 0.2 151743 5.04 0.2 16 1931 4.86 0.2 17 1995 4.73 0.2 18 1913 4.61 0.2 19 18814.52 0.2 20 1837 4.43 0.2 21 1885 4.36 0.3

1. A method comprising the steps of: a) treating a subterranean site ina zone adjacent to a water injection well with a detoxifying agentwherein, prior to the treatment, corrosion inhibitors and theirdegradation products have been adsorbed into the zone and haveaccumulated to concentrations that are toxic to microorganisms used inmicrobial enhanced oil recovery and/or bioremediation processes, andthereby have formed a toxic zone, and b) adding an inoculum ofmicroorganisms wherein the microorganisms comprise one or more speciesof: Comamonas, Fusibacter, Marinobacterium, Petrotoga, Shewanella,Pseudomonas, Vibrio, Petrotoga, Thauera, and Microbulbifer useful inmicrobial enhanced oil recovery to the water injection well wherein thecorrosion inhibitor comprises an organic compound selected from thegroup consisting of organic phosphonates, organic nitrogen compoundssuch as amines, organic acids and their salts and esters, carboxylicacids and their salts and esters, sulfonic acids and their salts.
 2. Themethod of claim 1 wherein the corrosion inhibitor comprises quaternaryammonium compounds or their degradation products.
 3. The method of claim2 wherein the quaternary ammonium compound is selected from the groupconsisting of benzalkonium chloride, bis-quaternary ammonium salts,quaternary nitrogen compounds and imidazoline compounds.
 4. The methodof claim 1 wherein the detoxifying agent of (a) is also a dispersingagent.
 5. The method of claim 4 wherein the dispersing agent is an acidselected from the group consisting of hydrochloric acid, nitric acid,hydrofluoric acid, acetic acid and oxalic acid.
 6. The method of claim 4wherein the dispersing agent causes disassociation of the corrosioninhibitor from the subterranean site adjacent to the water injectionwell and disperses and dilutes it such that the corrosion inhibitorbecomes non-toxic to the microorganisms and the subterranean siteadjacent to the water injection well is detoxified.
 7. The method ofclaim 6 wherein the dispersing agent is hydrochloric acid.
 8. The methodof claim 6 wherein the dispersing agent is nitric acid.
 9. The method ofclaim 6 wherein the acid is at a concentration from about 0.1 weightpercent to about 20 weight percent.
 10. The method of claim 1 whereinthe corrosion inhibitor of step (i) is a growth inhibitor of sulfatereducing bacteria.
 11. The method of claim 6 wherein the microorganismscolonize the detoxified subterranean site adjacent to the waterinjection well to perform microbial enhanced oil recovery.